This invention relates to improved recovery of petroleum from an underground reservoir. More particularly the invention discloses injection of gases that are miscible in crude oil to effect enhanced recovery, as well as to induce the separation of hydrogen for capture apart from the crude oil.
It is well known in the art that certain gases are readily soluble in crude oil. Such gases when taken into solution cause the crude oil to expand, reduce its viscosity and otherwise change its physical characteristics in manners that facilitate production. The most abundant gas dissolved in crude oil is natural gas of petroleum origin, which in many crude oil reservoirs provides the drive for primary production. Some crude oil reservoirs have little or no natural gas content, a factor that indicates difficulties in attempts to produce the petroleum at optimum levels.
For petroleum reservoirs devoid of natural gas, production performance often can be enhanced by injecting natural gas under pressure into the reservoir. Due to the current general shortage of natural gas, such injection may not be appropriate either from a regulatory point of view of from an economic point of view. Thus other gases that are miscible in crude oil are promising candidates for use in enhanced recovery. Such gases include carbon dioxide, carbon monoxide, nitrogen, and hydrogen. As a general rule such gases must be available in copious supplies at reasonable costs at the oil field site. Generally hydrogen is a relatively expensive gas except in special circumstances as will be described later. The other gases-- CO.sub.2, CO and N.sub.2 -- are common products of combustion, together with water vapor, in the burning of hydrocarbons, and thus can be made readily available at the oil field. Unfortunately in the burning of hydrocarbons with air at relatively high combustion temperatures some of the nitrogen combines with oxygen. With concentrations of NO.sub.2 as low as 400 parts per million, a million cubic feet of inert exhaust gas can contain 45 pounds of nitric acid, resulting in a corrosive gas that is unsuitable for compression. Generating exhaust gases at temperatures in the lower range and thus avoiding formation of nitrous oxides is highly desirable as will be described later.
Injecting various miscible gases into petroleum reservoirs is well known in the art. In U.S. Pat. No. 1,697,260 of Cloud, various procedures are taught to inject hydrogen, carbon dioxide, carbon monoxide, and acetylene to absorb, dilute and liberate oil. In U.S. Pat. No. 2,173,556 of Hixon, methods are taught to inject heated products of combustion to dilute and displace crude oil. Other methods of dissolving gases into crude oil and displacing the crude to production wells are taught in U.S. Pat. Nos. 1,899,497 of Doherty, 2,297,832 of Hudson, 2,623,596 of Whorton, 2,885,003 of Lindauer, 2,936,030 of Allen and 3,075,918 of Holm.
Generally it is undesirable to consume petroleum products at the oil field site for the sole purpose of generating miscible gases to be used for injection into the petroleum reservoir. The situation is improved considerably when combustion is conducted for another purpose, such as developing power for compressors or firing boilers to raise steam. In these cases the products of combustion, normally wasted to the atmosphere, can be diverted for injection into the petroleum reservoir. If the fuel used is of petroleum origin, the problem of nitric acid in the exhaust gases generally must be solved prior to compression for injection underground. Also the local use of petroleum fuels may not be the most beneficial use of such fuels when substitute fuels are readily available.
It is not uncommon to find abundant supplies of coal at or near the sites of oil fields. Coal is an excellent fuel that provides products of combustion useful in the enhanced recovery of petroleum. Also combustion temperatures are more readily controlled to minimize or prevent the generation of nitric acid in the products of combustion.
In the early part of the twentieth century, before natural gas of petroleum origin was widely available, most city gas systems distributed "town gas" that was generated from coal. Such gas was manufactured in above ground pressure vessels by charging each vessel with coal, setting the coal afire, bringing the coal up to incandescent temperature with an air blast then producing water gas with a steam run with production continuing with alternate cycles of air blast, steam run. It is important to note that incandescent temperature of coal is in the order of 2000.degree. F. in contrast to the flame temperature of petroleum fuels which often is in the order of 4000.degree. F. The products of combustion from the air blow commonly are called producer gas which has a heat content of about 100 to 160 BTU per standard cubic foot, a gas that is useful in raising steam. Producer gas normally does not contain nitric acid. Producer gas-- composed primarily of CO.sub.2, N.sub.2, CO and water vapor-- also is a useful gas in the enhanced recovery of petroleum. Water gas generated by the steam run is composed principally of hydrogen and carbon monoxide and has a heat content of more than 300 BTU per standard cubic foot. Producing hydrogen in this manner results in a relatively low cost source of hydrogen.
Producer gas and water gas can be produced from coal in situ, as is well known in the art. U.S. Pat. Nos. 4,018,481 and 4,114,688 of Terry teach methods of producing these gases from coal in situ. U.S. Pat. No. 3,809,159 of Young et al teaches methods of using gases produced from underground coal in the enhanced recovery of petroleum.
Generally the water gas manufactured in above ground gas generators is comparable to that generated from coal in situ. The composition of producer gas varies somewhat due to the fact that in situ gasification is conducted in wet coal seams to preclude the possibilities of a run away burn underground. As a result the hydrogen content of in situ producer gas is generally higher than in the case of mechanical gas generators, as is shown in a typical volumetric dry composition of producer gas from both sources:
TABLE 1 ______________________________________ Mechanical Generator In Situ ______________________________________ H.sub.2 10.5 17.3 CO 22.0 14.7 CO.sub.2 5.7 12.4 N.sub.2 58.8 51.0 Other 3.0 4.6 BTU/FT.sup.3 136 152 ______________________________________
In the prior art involving injection of miscible gases into petroleum reservoirs virtually all of the art is directed toward increasing the mobility of crude oil and providing additional pressure to the reservoir. Mobility is enhanced by dissolving the gases into crude oil causing swelling with a corresponding decrease in viscosity. If heat also is added, a further decrease in viscosity will occur.
While the characteristics of crude oil varies considerably from reservoir to reservoir, solubility capability of a medium grade crude oil at a reservoir pressure of 2000 psi and a temperature of 120.degree. F. could be, in standard cubic feet per barrel:
TABLE 2 ______________________________________ hydrogen 68 carbon dioxide monoxide 83 nitrogen 70 natural gas 660 carbon dioxide 1200 ______________________________________
While a barrel of crude oil contains a volume of 5.6 cubic feet at atmospheric pressure, at the elevated pressure of a reservoir approximately 5,000 feet deep, a barrel of crude can take into solution large volumes of miscible gases as shown in Table 2. It should be noted that the solubility of one gas is substantially unaffected by the presence of another gas. Thus if the object of an enhanced recovery procedure is to cause crude oil to swell, the preferred gas from Table 2 above would be carbon dioxide.
The host rock in a crude oil reservoir is not a homogenous substance and its porosity and permeability can vary widely from place to place in the reservoir. If a gas is to be dissolved in a crude oil it is first necessary to cause the gas to diffuse throughout the reservoir. While carbon dioxide has good miscibility properties, it is somewhat lacking in diffusion properties as is seen in the following comparison where the diffusion rate of carbon dioxide is taken at unity:
TABLE 3 ______________________________________ carbon dioxide 1.0 nitrogen 1.6 carbon monoxide 1.6 natural gas 1.5 hydrogen 22.0 ______________________________________
Thus it is apparent that hydrogen, with its low solubility capability, can be expected to move relatively rapidly through the petroleum reservoir when injection quantities are relatively large. It is this attribute of hydrogen that is of particular interest in the present invention. It will be appreciated that this invention is not limited by any theory of operation, but any theory that has been advanced is merely to facilitate disclosure of the invention.
In the primary recovery of petroleum one of the most favorable reservoirs for maximum recovery is the case where the reservoir has a cap of natural gas and natural gas is in solution within the crude oil. There are many reservoirs, however, where no gas cap exists, and it is this case that is of particular interest in the present invention.
It is an object of the present invention to inject gases that are miscible in crude oil into a petroleum reservoir to create an artificial gas cap thereby providing enhanced recovery of the petroleum. It is another object of the present invention to inject a miscible gas mixture composed of hydrogen and other gases so that the first gas to form the gas cap is a mixture composed substantially of hydrogen. It is another object of the present invention to capture the mixture of gases, composed substantially of hydrogen, apart from the recovery of crude oil. Other objectives, capabilities and advantages of the present invention will be apparent as the description proceeds and in conjunction with the drawings.